This invention relates generally to diagnosis of a hydrocarbon-bearing formation and more specifically, to a method for estimating a property of a hydrocarbon-bearing formation penetrated by injection and production wells.
A significant fraction of the oil-in-place is left in the ground after primary recovery. Water injection, sometimes referred to as waterflooding, and gas injection, sometimes referred to as gas flooding, are used as improved oil recovery processes to recover the remaining oil. The terms xe2x80x9cgas injectionxe2x80x9d and xe2x80x9cgas floodingxe2x80x9d typically refer to an oil recovery process in which the fluid injected is a hydrocarbon gas, inert gas, carbon dioxide or steam. Water and gas may be injected alternately in a process referred to as water-alternating-gas (WAG) flooding.
The success of water and gas floods can be diminished by early breakthrough of the injected water and/or gas at production wells. A particularly serious problem is early breakthrough caused by channeling of the injectant through high-permeability pathways connecting certain injection wells to the xe2x80x9cbreakthroughxe2x80x9d production wells. The pathways may consist of thin high-permeability layers or xe2x80x9cthief zones,xe2x80x9d networks of higher-permeability rock, or systems of natural or induced fractures. Such channeling, or poor conformance, of the injected fluid can cause it to contact and sweep only a small portion of the reservoir volume, thus limiting the amount of oil recovered and causing inefficient utilization of the injected fluid.
Channeling can be further exacerbated by unfavorable mobility and density ratios between the injected and reservoir fluids, which cause the injected fluid to finger through the resident reservoir fluids and to gravity segregate in the reservoir. Fingering and gravity segregation are particular concerns in gas or WAG injection, because gases have higher mobility and lower density than oil or water.
A variety of remedial actions have been proposed to mitigate channeling problems. The rate of fluid production at the offending production well may be reduced or the well may be shut in periodically to limit production of the injected fluid. If the source well for the unwanted production can be identified, the rate of injection at that well can be reduced. Plugging substances such as cements, gels, polymers, foams, or combinations thereof may be placed in the high-permeability pathway to block flow and divert injected fluids into other less permeable regions of the reservoir.
The choice of the most appropriate remedial action depends critically upon identifying the source well for the undesired production and characterizing the volume and transmissibility of the high-permeability pathway between the source well and the offending production well. Tracer surveys, pressure interference tests, and pressure pulse tests have been used to identify and characterize high-permeability pathways between wells. These techniques can be expensive and time-consuming because special injection and production sampling equipment and procedures are required. A significant need therefore exists for a technique that would enable rapid screening of interwell communication using readily available historical data, with minimal disruption of existing production operations.
It has been suggested that statistical correlation techniques may be applied to correlate fluctuations in injection and production rates and thereby characterize interwell communication. Statistical correlation analysis is used to determine whether two ranges of data move together, i.e., whether large values of one set (such as injection rate) are associated with large values of the other (such as production rate), corresponding to positive correlation, whether small values of one set are associated with large values of the other, corresponding to negative correlation, or whether values in both sets are unrelated, corresponding to correlation near zero.
A paper by Chou, S. I., Bae, J. H., Friedman, F., and Dolan, J. D., xe2x80x9cDevelopment of Optimal Water Control Strategies,xe2x80x9d SPE 28571, presented at the SPE 69th Annual Technical Conference and Exhibition, New Orleans, La., Sep. 25-28, 1994, describes a methodology for assessing the degree of communication between a water injection well and offset production wells. Random fluctuations in water injection rate were correlated with fluctuations in water production rate at surrounding wells. A high correlation coefficient was assumed to indicate the presence of a dominant thief zone. Simulations with idealized reservoir models exhibited a maximum correlation coefficient at a specific time delay, which was assumed to be caused by reservoir compressibility (mostly due to gas). However, actual field data did not exhibit a maximum correlation coefficient at a specific time delay. Rather, the correlation coefficient was uniformly high or low for all time delays. Gel treatments in injection wells having high correlation with offset high-water-cut producers resulted in generally positive producer response. However, the authors indicated that it was not possible to determine the optimal gel volume in advance; instead, it was determined by injectivity changes during gel emplacement.
A paper by Heffer, K. J., Fox, R. J., McGill, C. A., and Koutsabeloulis, N. C., xe2x80x9cNovel Techniques Show Links between Reservoir Flow Directionality, Earth Stress, Fault Structure and Geomechanical Changes in Mature Waterfloods,xe2x80x9d SPE 30711, presented at the SPE 70th Annual Technical Conference and Exhibition, Dallas, Tex., Oct. 22-25, 1995, proposed using correlations between fluctuations in injection and production well rates to indicate communication in oil reservoirs. The direction of maximum correlation was found to correspond to the local orientation of maximum horizontal earth stresses, which was assumed to correspond to the direction of highest permeability and most rapid fluid flow. The correlation analysis assumed zero time delay between injection and production rate changes; nevertheless, significant correlations were found between wells separated by large distances.
A paper by Jansen, F. E., and Kelkar, M. G., xe2x80x9cExploratory Data Analysis of Production Data,xe2x80x9d SPE 35184, presented at the SPE 1996 Permian Basin Oil and Gas Recovery Conference, Midland, Tex., Mar. 27-29, 1996 proposed a method for assessing interwell communication in a waterflood. Fluctuations in water injection rate were correlated with fluctuations in water production rate at surrounding wells. The correlation was based on the assumption that a rate change in an injection well could generate a pressure pulse that translates to an instantaneous rate change in a production well; it was stated that xe2x80x9cit is not obvious how to interpret any correlation above zero time lag.xe2x80x9d This correlation method was claimed to be a useful tool for indicating possible communication between wells. However, the authors indicated that the method has limitations caused by the complex interaction between operating conditions, reservoir response, and pressure superposition between injectors. As a result, it was suggested that the method worked best when there is a minimum of noise in the data and a strong direct relationship between the wells.
These publications suggest that correlations between fluctuations in injection rate and fluctuations in production rate may be used to indicate communication between injection and production wells. However, because the methods rely upon correlation of random fluctuations, there can be substantial ambiguity in the interpretation of the correlations. Furthermore, the methods used in the past do not provide information about formation properties (such as channel volume, permeability, or transmissibility) between the wells. Such information is critical for selection and design of remedial actions. There is a continuing need for an improved method of analysis that reduces ambiguity and enables the characterization of interwell properties.
This invention provides a method of estimating a property of a hydrocarbon-bearing formation penetrated by at least one injection well, preferably a plurality of injection wells, through which fluid is injected into the formation and penetrated by at least one production well through which fluid is produced from the formation. In carrying out the method, the injection rates of fluid through the injection wells are periodically varied and measured at substantially regular time intervals. The production rate of fluid produced through the production well is also measured. A series of production well response delays, xcfx84, are selected. A set of correlation coefficients between the injection rate for each injection well and the production rate as a function of xcfx84 are determined. From each set of correlation coefficients, a time lag, xcfx84max, corresponding to the maximum correlation coefficient is determined. The xcfx84max is then used to characterize a formation property, such as channel volume, permeability, or transmissibility.